In the production of oil from subterranean formations, it is usually possible to recover only a small fraction of the total oil present in the formation by so-called primary recovery methods which utilize only the natural forces present in the reservoir. To recover oil beyond that which is produced by primary methods, a variety of supplemental production techniques have been employed. In these supplemental techniques, commonly referred to as secondary recovery operations, a fluid is introduced into the oil-bearing formation in order to displace oil to a production system comprising one or more production wells. The displacing or "drive" fluid may be an aqueous liquid such as brine or fresh water, a gas such as carbon dioxide, steam or dense-phase carbon dioxide, an oil-miscible liquid such as butane, or an oil and water-miscible liquid such as an alcohol. Often, the most cost-effective and desirable secondary recovery methods involve the injection of an aqueous or carbon dioxide flooding medium into an oil-bearing formation, either alone or in combination with other fluids. In practice, a number of injection and production wells will be used in a given field arranged in conventional patterns such as a line drive, five spot or inverted five spot, seven spot or inverted seven spot.
In the use of the various flooding techniques, it has become a common expedient to add various polymeric thickening agents to the drive fluid to increase its viscosity to a point where it approaches that of the oil which is desired to be displaced, thus improving the displacement of oil from the formation. The polymers used for this purpose are often said to be used for "mobility" control.
Another problem encountered is that certain injected drive fluids may be much lighter than the reservoir fluids and thus separate by gravity, rising toward the top of the flowing region and resulting in the bypassing of the lower regions. This phenomenon is known as gravity override.
Also encountered in the use of various flooding techniques is a situation caused by the fact that different regions or strata have different permeabilities. In this situation, the drive fluid preferentially enters the regions of higher permeability due to the lower resistance to flow present rather than the regions of low permeability where significant volumes of oil often reside.
It therefore is often desirable to plug the regions of high permeability, or "thief" zones, either partly or entirely, so as to divert the drive fluid into regions of lower permeability. The mechanical isolation of these thief zones has been tried but vertical communication among reservoir strata often renders this method ineffective. Physical plugging of the high permeability regions by cements and solid slurries has also been tried with varying degrees of success; however, these techniques have the drawback that still-productive sites may be permanently closed.
As a result of these earlier efforts, the desireability of designing a viscous slurry capable of sealing off the most permeable layers so that the drive fluid would be diverted to the underswept, "tighter" regions of the reservoir, became evident. This led to the use of oil/water emulsions, as well as gels and polymers for controlling the permeability of the formations. This process is frequently referred to as "profile" control, a reference to the control of the vertical permeability profile of the reservoir. Profile control agents which have been proposed include oil/water emulsions, gels, e.g., lignosulfate gels and polymers, with polymers being the most extensively applied in recent years.
Of the secondary and tertiary enhanced oil recovery processes, waterflooding, carbon dioxide flooding, miscible or immiscible gas flooding and steam flooding are of particular interest and importance. As indicated, profile control can often improve performance in such processes by reducing the effect of permeability inhomogeneity or stratification and gravity override. A gel suitable for profile control must be stable enough to continue to impede flow for long periods of time at the given temperature, salinity and pH of a particular oil-bearing reservoir. A gel must also have adequate mechanical strength to resist the pressures which will be applied during the subsequent oil recovery flooding step. There are a variety of materials commercially available for profile control, all of which perform differently and have their own, often unique limitations.
Among the many polymers examined thus far are polyacrylamides, polysaccharides, celluloses, furfural-alcohol and acrylic-epoxy resins, silicates and polyisocyanurates. A major part of the work conducted in this area has dealt with polyacrylamides. Polyacrylamides have been used both in their normal, non-crosslinked form as well as in the form of crosslinked metal complexes, as described, for example, in U.S. Pat. Nos. 4,009,755, 4,069,869 and 4,413,680. Shear degradation during injection and sensitivity to reservoir brines tend to diminish the beneficial effects derived from these polyacrylamides.
Proposals have been made for the use of inorganic polymers, especially inorganic silicates, as permeability control agents. For example, U.S. Pat. Nos. 4,009,755 and 4,069,869 disclose the use of inorganic silicates for this purpose. In the permeability control method described in these patents, an organic polymeric permeability control agent such as a crosslinked polyacrylamide or polysaccharide is first injected into the reservoir, followed by an aqueous solution of an alkaline metal silicate and a material that reacts with the silicate to form a silicate gel which plugs the high permeability regions in the formation. An alkaline metal silicate is typically used as the source of silica and the gelling agent is usually an acid or acid-forming compound such as a water soluble ammonium salt, a lower aldehyde, an aluminum salt or an alkaline metal aluminate.
The problem, however, with many inorganic silicates is that their solutions are often quite viscous and stable only under alkaline conditions. As soon as conditions become acidic, a silicate gel is formed. Although this is the desired reaction for plugging the formation, it may occur prematurely. For example, gelation may begin before the solution has had an adequate opportunity to enter the high permeability regions of the formation, cutting off the possibilities for further injection of plugging material.
Other attempts have been made to achieve profile control. One such attempt is described in U.S. Pat. No. 4,498,539 to Bruning, which discloses delayed gelable compositions for injection of a water thickening amount of a polymer capable of gelling in the presence of a crosslinking agent so that after the composition has penetrated into an underground formation and positioned itself preferentially in the highly permeable strata, the delayed gelation is triggered by in-situ hydrolysis of an ester which reduces the pH of the composition to the gelable range thereby producing in-depth plugging of the strata with the gelled polymer.
Another group of polymeric thickeners which has received considerable attention for use in waterflooding is xanthan polysaccharides. Xanthan polysaccharides are produced by the action of bacteria of the genus Xanthomonas on carbohydrates. For example, U.S. Pat. Nos. 3,757,863 and 3,383,307 disclose mobility control by the use of polysaccharides in the presence of polyvalent metal ion crosslinking agents. U.S. Pat. No. 3,810,882 discloses the possibility of using certain reducible complex metal ions as cross-linking agents for polysaccharides. U.S. Pat. Nos. 4,078,607 and 4,104,193 describe a method for improving the efficiency of waterflooding operations by a particular polysaccharide prehydration technique. U.S. Pat. No. 4,413,680 describes the use of crosslinked polysaccharides for selective permeability control in oil reservoirs.
U.S. Pat. No. 3,908,760 describes a polymer waterflooding process in which a gelled, water-soluble Xanthomonas polysaccharide is injected into a stratified reservoir to form a slug, band or front of gel extending vertically across both high permeability and low permeability strata. This patent also suggests the use of complexed polysaccharides to block natural or man-made fractures in formations. The use of polyvalent metal ions for crosslinking xanthan polysaccharides and other polymers which are to be used for permeability control is described in U.S. Pat. Nos. 4,009,755, 4,069,869 and 4,413,680. The use of phenol/aldehyde crosslinking agents with xanthan polysaccharides and other polymers is disclosed in U.S. Pat. Nos. 4,323,123 and 4,440,228.
Another type of polysaccharide which has been experimented with in the area of profile control is the non-xanthan, heteropolysaccharide S-130. S-130 belongs to the group of non-xanthan welan gums. S-130 is produced by fermentation with a microorganism of the genus Alcaligenes. Another welan gum heteropolysaccharide, known as S-194, is also produced by fermentation with a microorganism of the genus Alcaligenes. A notable characteristic of the heteropolysaccharide S-130 is that it develops a high viscosity in saline waters. This is particularly so in brines which contain divalent cations such as Ca.sup.2+ and Mg.sup.2+ or monovalent cations such as Na+ and K+.
U.S. Pat. No. 4,658,898 discloses the use of welan gum S-130 in saline waters. Crosslinking with trivalent cations, such as chromium, aluminum, zirconium and iron is also disclosed. Additionally, crosslinking with organic compounds containing at least two positively charged nitrogen atoms is disclosed in U.S. Pat. No. 4,658,898, which is hereby incorporated by reference in its entirety.
Ser. No. 940,682 filed Dec. 11, 1986, now U.S. Pat. No. 4,787,451 the inventor of which is also a co-inventor of the present invention, discloses the use of melamine-formaldehyde and other amino resins to crosslink various polymers including the welan gum heteropolysaccharide S-130. Ser. No. 940,682 is hereby incorporated by reference in its entirety.
One problem which has continually attended the use of organic polymers as profile control agents is that of stability in the reservoir. This requires not only that the gel formed by the polymer should be stable enough to withstand the relatively high temperatures encountered in some reservoirs -in itself, a difficult requirement - but also that the gel should be stable over as wide a range of pH conditions as possible so that the polymer will have the potential of being used in reservoirs of different kinds, e.g. sandstone, carbonate rock and others. Stability to various oilfield brines is another desirable requirement. Many of the known types of organic gel forming polymers are unsatisfactory in one respect or another, e.g. temperature stability, brine stability, pH range, so that there has been a continuing need for new and different polymers for permeability control purposes.
While the welan gum heteropolysaccharide S-130 will gel in the presence of high salinity brines, in lower salinity or softer brines it will not gel.
Accordingly, it is an object of the present invention to provide an improved aqueous crosslinked gel of a welan gum heteropolysaccharide and phenolic resin or phenol/aldehyde mixture which is useful in a lower salinity oil-bearing reservoir environment.
It is another object of this invention to provide a substantially more stable gel for use when high temperatures are encountered.
It is a further object of this invention to provide a process for selectively plugging regions of higher permeability within an oil-bearing subterrranean formation to obtain improved sweep efficiency during a fluid flood oil recovery operation.